This invention relates to a method for improving the quality of a formation fluid sample. In particular, the invention relates to a real-time method for determining the composition of a formation fluid and/or differentiating between oil-base filtrates and formation fluid hydrocarbons during the process of pumping fluids from a downhole formation for the purpose of taking a formation fluid sample.
It is desirable to evaluate formation fluids that may indicate the existence and/or type of subsurface hydrocarbon fluid reservoirs. To assist in this evaluation, wireline formation tester tools are commonly used during openhole logging operations to recover formation fluid samples and to determine the type and distribution of formation fluids. Methods of positive fluid type identification usually come from inspection and/or analysis of recovered samples at the surface. As a result of these methods there are long-standing difficulties associated with wireline fluid sampling operations such as: mud filtrate invasion into the formation fluid, establishing and maintaining a seal between the tool probe and the borehole wall, and drawing down the pressure of the formation fluid below saturation pressure. These and other issues are addressed by downhole tools such as the tool described in U.S. Pat. Nos. 4,860,581 and 4,936,139 issued to Zimmerman et al.
The Zimmerman patents disclose a downhole tool that can take formation fluid samples and determine formation properties from these samples. These downhole wireline tools may be modularly constructed so that a tool can perform multiple tasks in a single descent of the tool into the borehole. FIG. 1 shows such a downhole tool. This tool 1 has a probe module 2 that establishes fluid communication between the tool and the earth formation 3 via a probe 4. This tool contains a pump out module 5 for pumping fluid from the formation into the tool and a module 6 to analyze fluid from the earth formation.
FIG. 1 illustrates the problems associated with taking a formation fluid sample. The formation 3 contains a mixture of both the desired hydrocarbon type fluid 7 and the undesired contaminated fluid filtrates 8. The less contaminated hydrocarbon fluid is often referred to as the xe2x80x98clean fluidxe2x80x99. The borehole annulus 9 also contains contaminated filtrates. Contaminated formation fluid 8 is in closer proximity to the borehole and a greater portion of that fluid is initially in the mixture. During the pump out process, the composition of this mixture will continually change until the composition begins to stabilize. From the fluid analyzer 6, it is determined when the composition of the fluid begins to stabilize. Once fluid stabilization has occurred, and depending on the portion of hydrocarbon in the mixture, the incoming fluid may be diverted into the sample chamber 10. However, during any attempt to retrieve the clean fluid, it will be necessary to pump out the contaminated formation fluids before getting to the desired clean formation fluid.
In addition to the mixture of contaminated and clean fluids, other factors can affect the fluid sample quality. These factors include the rock properties, the mud filtrate invasion volume, the pressure differential used to produce the fluid, and the clean up time. The rock properties usually cannot be modified, but selection of the sample interval can alter the influence of the vertical permeability in some cases. The fluid flow geometry into a probe 4, even under stable conditions, can include a significant vertical component from the borehole-invaded zone that contains mud filtrate contamination. Sample points taken near vertical flow barriers can reduce the influx of mud filtrate into the probe.
Drilling operations to create the borehole require various types of drilling muds. The use of oil-based drilling mud systems causes major problems in wireline logging including problems during attempts to obtain high quality fluid samples. These mud filtrate fluids are mixed in the formation oil. Therefore, quantification of the oil-base material in the formation oil becomes difficult without laboratory analysis. The presence of even small volumes of oil-base filtrate in the sample can significantly alter the pressure-volume-temperature (PVT) properties of formation oil. Generally, the additives in the filtrate change the character of the optical density response curves of the oil-based mud filtrate. This change affects the optical analysis of the filtrate and increases the difficulty of distinguishing an oil-based filtrate from a formation hydrocarbon fluid. Because of this difficulty in making this distinction, the quality of a fluid sample may be unreliable.
One conventional sample taking method that addresses this problem is to pump fluid from the formation through the tool for a predetermined period of time or a predetermined pumped volume of fluid. It is assumed that after this period, the fluid passing though the tool should be at an acceptable contamination level. Although using empirical models or reservoir simulators to estimate the time required to obtain an acceptable fluid sample is appealing in concept, it requires significant knowledge of the formation rock properties, formation fluids, mud filtrate, mud cake, formation damage zone, flow patterns, and other information in the near wellbore zone which is not available.
A second approach is explained using the tool in FIG. 1. A downhole tool 1 is suspended in a borehole 9 from a wireline 11 or drill pipe. In this method, a probe 4 in fluid communication with the tool body is also in contact with the borehole wall 12. To retrieve the formation fluid, a pressure drop is created in the tool across the probe. This pressure drop causes formation fluid to flow from the high-pressure formation to the lower pressure probe and into the tool. The pumpout module 5 is used to draw fluids from the formation, through the tool flowline 13 and out into the borehole (if desired). As fluids pass through the tool, the probe module measures their resistivity and temperature and the optical fluid analyzer (OFA) 6 measures their optical properties (i.e. fluid density).
Optical data are processed in real-time to quantitatively determine flowing oil and water fractions, and to obtain a qualitative indication of the amount of free gas in the flow system. Optical fluid responses vary for different materials. As shown in FIG. 2, there are significant differences between water and oils. The responses of water 14 and oils 15 and 16 show these differences When the fluid analysis begins to show stabilization, a fluid sample is taken by diverting fluid into a sample chamber.
A flowline 13 passes though two independent optical sensors in the OFA module 6. In one sensor, absorption spectroscopy is used to detect and analyze liquid. In the other sensor, a special type of optical reflection measurement detects gas. These detections allow wellsite personnel to decide whether to divert the fluid flow into a sample chamber for retrieval, to continue to expel the fluid into the borehole or to a dump chamber, or to increase the sampling pressure above bubblepoint. This module can also verify that the formation contains only water or only gas and/or that a sample is not necessary. Thus, the sample chambers in the tool are kept available only for desired fluids. After a decision has been made to switch from pumpout mode to sampling mode, the OFA module continues to monitor the fluid in the flowline, particularly to verify that production remains above bubblepoint.
As stated, the OFA module has a visible and near-infrared absorption spectrometer for oil/water discrimination and a refractometer for free gas identification. Each OFA sensor responds to one of two basic optical properties, namely absorption and index refraction. These properties are measured by passing light through a window opening onto the flowline. The measured absorption spectra depend on the composition of the sampled fluid. FIG. 2 shows OFA responses of different formation materials in terms of optical density. Optical density is defined as the logarithm of the inverse of light transmittance for several fluids. The optical responses are a plot of the optical density of the material versus wavelength ranges. FIG. 2 shows standard responses for water 14, light oil 15 and heavy oil 16. Notice that water 14 and oils 15 and 16 respectively have considerably different light absorption in the near-infrared region (approximately 700 nm-2400 nm). Water has an absorption peak at 1450 nanometers (nm); the oils have an absorption peak at about 1720 nm. This difference makes it possible to readily distinguish between water and oil in the OFA. Condensates 17 and oil-based filtrates 18 have absorption peaks that are similar to the oils. The distinction between oils and filtrates is not as clearly defined.
Another important feature of the OFA is the ability to differentiate between light and heavy oils by identifying wavelengths of the responses. Hydrocarbons typically have shorter wavelengths and are absorbed before longer wavelengths of water. The selective absorption of wavelengths results from the proportion of complex molecules, such as asphaltenes, present in the oil. As the proportion of heavier hydrocarbon molecule chains increase, more of the shorter wavelengths are absorbed.
A requirement to insure the recovery of quality fluid samples is a detection system capable of indicating fluid types in addition to water and oil. The sensor in the probe module 2 generally performs this identification function by providing a resistivity measurement over a wide range fluids. However, some conditions, and particularly wells drilled with oil-base mud (OBM), may require more optical fluid analysis from the OFA module to determine the additional fluid types. This module can use optical analysis techniques to identify the various fluids in the flowline of the tool.
Although the above methods attempt to address the problem of obtaining a cleaner formation fluid sample by identifying whether water and oil are present in a fluid, these methods do not address the problem of identifying the type of fluid in the sample or the percentage of each type of fluid in the sample. One discussion of solutions to this problem was presented in SPE Paper No. 39093, published in October 1997. This solution used a database of responses along with other formation data to simulate flow rates and give an estimate of the pumpout time needed to obtain an acceptable fluid sample. In addition, this method requires certain data regarding the downhole conditions of the formation, such as API gravity and density, which is not initially available.
There remains a need for a technique that can determine in real-time the composition of formation fluid flowing through a downhole tool during a sample-taking operation. There also remains a need for a technique that determines the relative amounts of the fluids in the sample in order to determine whether there is an acceptable level of the desirable formation fluid in the sample.
It is an objective of this invention to provide a reliable and real-time method for improving the quality of a formation fluid sample taken downhole.
Another objective of this invention is to determine the composition of hydrocarbons, waters, highly absorbing fluids and downhole filtrates in the formation fluids.
Another objective of this invention is to monitor in real-time the formation fluid flowing into a downhole tester tool in order to determine the appropriate time to take the fluid sample.
A fourth objective of this invention is to differentiate between oil-based fluid filtrates and formation hydrocarbon fluids.
Another objective of this invention is to distinguish between light hydrocarbon fluids and heavy hydrocarbon fluids.
Another objective of this invention is to use fluid characteristic curves to quantitatively describe the formation fluid.
Another objective of this invention is to use fluid optical density to determine fluid activity.
The present invention provides a technique to determine in real-time, the composition of fluid being pumped into a downhole tester tool. This technique determines the relative portion of hydrocarbons (oil), water, filtrates and solids in the formation fluid flowing into the tool during the sample taking process. Since this fluid composition changes, the objective is to monitor the composition of the fluid flowing into the tool until the fluid composition contains an acceptable portion of the desired formation hydrocarbon fluid or until a decision is made not to take a fluid sample at that location. Once there is an acceptable level of hydrocarbon fluid flowing into the tool, the fluid flow into the tool is diverted into a sample chamber to collect a sample of the fluid.
This invention can use an optical fluid analyzer (OFA) in a downhole tester tool to analyze the incoming fluid. As previously described the OFA monitors the fluid in the flowline using a sensor system (an optical spectrometer and an optical gas detector) closely spaced along the tool flowline. The OFA produces an optical spectrum (response) measured across a plurality of wavelength channels in the OFA. The different channels contain detectors that detect various light wavelengths transmitted through the OFA.
In the method of this invention, the OFA produces a measured absorption spectrum (log), of the inflowing fluid from the wavelengths detected at the various channels of the OFA. This spectrum is a combination of optical fluid responses representing hydrocarbons, water, solids and filtrates that compose the formation fluid, forming an array of the components of an optical emission passing through the formation fluid, separated and arranged according to wavelength. The present invention determines the composition of the measured absorbed light spectrum, and thereby which materials are present in the fluid and the portions of each material in the fluid. A premise of this invention is that the measured spectrum is the sum (i.e. linear, non-linear) of the various fluid responses.
The formation fluid composition is determined by comparing the measured spectrum to a composite spectrum of known responses for standard formation fluid materials. The present invention uses a database of optical density fluid responses from various fluid and gas materials to aid in the determination of the composite spectrum. The composite spectrum is generated from responses selected from the optical density fluid response database. The selected responses are combined to produce a composite spectrum. This composition spectrum is an estimation of the materials in the formation fluid.
A spectral fitting procedure is performed on the measured spectrum using the composite spectrum of database responses to determine the types of materials in the measured spectrum. During this fitting procedure, corresponding features of the composite spectrum are compared to features of the measured spectrum to determine the derivation between the two spectra. If the deviation between the two spectra is within an acceptable level, there is a best fit between the spectra. The composite spectrum is then used to determine the formation fluid composition. If this deviation is not acceptable, changes are then made in the fractional components of the composite spectrum using a weighted linear regression technique until the composite spectrum matches/fits the measured spectrum. After there is an acceptable match between the measured absorption spectrum and the composite spectrum, a determination is made from the resulting composite spectrum of the types and portions of each material in the fluid.